India's Power Sector: Natural Gas Based Power Plants – Problems and Prospects
By Venkateswar Jayanthy
India has the fifth largest
electricity generation capacity in the world with an aggregate generating
capacity of 181.56GW. However, its per capita consumption at 606 units is less
than half of China’s. India’s transmission and distribution (T&D) network
of 5.7 million circuit-km is the 3rd largest in the world. However, its T&D
losses are also among the highest in the world at over 31%.
Fuel
|
MW
|
%age
|
Total
Thermal
|
118409.48
|
65.21
|
-
Coal
|
99,503.38
|
54.80
|
-
Gas
|
17,706.35
|
9.75
|
-
Oil
|
1,199.75
|
0.66
|
Hydro (Renewable)
|
38,206.40
|
21.04
|
Nuclear
|
4,780.00
|
2.63
|
RES** (MNRE)
|
20,162.24
|
11.10
|
Total
|
1,81,558.12
|
100.00
|
Renewable Energy Sources(RES) include SHP, BG,
BP, U&I and Wind Energy, SHP=Small Hydro Project, BG=Biomass Gasifier,
BP=Biomass Power, U & I=Urban & Industrial Waste Power, RES=Renewable
Energy Sources (Source: Ministry of Power, GOI: http://powermin.nic.in/JSP_SERVLETS/internal.jsp)
|
GOI has been encouraging private sector participation with its policy
initiatives such as 100% FDI in Generation, Transmission and Distribution permitted
within the framework of Electricity Act 2003 and National Electricity Policy
2005. The mega power projects (above 1,000MW generation-capacity) are eligible
for waiver of import duties on capital goods. The units that come on stream
enjoy Income tax holiday for a block of 10 years in the first 15 years of
operation. These policy initiatives coupled with the formation of independent
Regulators, the Central Electricity Regulatory Commission at the Centre and the
State-level Electricity Regulatory Commissions have encouraged the private
sector to participate in the Sector, more particularly in the Generation of
power. GOI has been expecting the private sector to slowly but steadily take
the lead in the growth of installed capacity of power generation in the country
as can be seen from the Table here.
Plan
|
Capacities
Added/ Planned Addition
|
Central
|
State
|
Private
|
Total
|
IX (1997-2002)
|
4,504
|
9,450
|
5,061
|
19,015
|
X (2002-07)
|
12,165
|
6,244
|
2,671
|
21,080
|
XI (2007-12) Revised
|
21,222
|
21,355
|
19,797
|
62,374
|
Source: Mid-Term Appraisal of XI Plan by
Planning Commission, Chapter 15, pp 313.
|
Composition of capacities added in the X Plan
Period, which is the 1st milestone after the Electricity Act 2003 was
enacted indicates that the Private Sector added 2,671MW of generating capacity,
compared to 18,409MW by the Public Sector. Much of this additional capacity has
come from thermal segment in both the sectors.
However, in
the current, i.e., the XI Plan (2007-12), the capacity addition against the
targets is far from satisfactory as can be seen from the following Table:
Segment
|
Original Target for XI Plan
(MW)
|
Commissioned till Dec 31, 2009
(MW)
|
Expected Achievement of the Balance
Target for the Plan Period
|
Expected Achievement for the Plan
(%)
|
Likely
|
With High Degree of Probability
(Revised target)
|
Best Efforts basis
|
Likely (%)
|
Higher Degree of Probability
(Revised target) (%)
|
Best Efforts basis (%)
|
Central
|
36,874
|
4,990
|
16,232
|
21,222
|
4,530
|
58%
|
71%
|
26%
|
State
|
26,783
|
9,112
|
12,243
|
21,355
|
1,130
|
80%
|
114%
|
38%
|
Private
|
15,043
|
4,990
|
14,808
|
19,797
|
6,930
|
132%
|
165%
|
79%
|
Total
|
78,700
|
19,092
|
43,282
|
62,374
|
12,590
|
79%
|
104%
|
40%
|
Source:
Mid-Term Appraisal of XI Plan by Planning Commission, Chapter 15, pp 313.
|
Even with the
extensive participation by the Private Sector, Plan targets are unlikely to be
achieved. If the current trend continues, the lofty targets of GOI may not
materialise in the near future, resulting in continued shortage of power supply
which will only curtail the full potential of the economy to grow. So what are
the issues that are clogging the highway to creating the generating capacities
in the country? A case in point is the gas based power plants in Andhra Pradesh.
The Natural Gas (NG) based power plants have been suffering despite being in
proximity to the source of Natural Gas. It is a case of ‘Water, water
everywhere, but not a drop to drink’!
AP Gas Based Power Plants – All Gas?
Andhra Pradesh has been a pioneer in power generation in the private sector. The first of the power plants in private sector in India commenced their operations in the east coast near Kakinada. Today the aggregate installed capacity of nine Natural Gas Based Power Plants (GBPPs) in AP stands at 2,782MW. Of this, 8 are Independent Power Producers (IPPs) accounting for 2510MW and the balance 272MW is a collective captive plant of APGPCL. The power plants by IPPs were set up after they signed agreements for supply of gas by ONGC through GAIL. It however turned out later that ONGC could not supply gas as scheduled. The prospects improved significantly with the gas find in Krishna-Godavari (KG) Basin by Reliance Industries Ltd (RIL) on the coast of AP. The IPPs would have faced extreme difficulty, had gas supply from RIL not materialised. With gas find in KG Basin, everyone thought the period of power shortages was over. The truth is far from it.
The problems afflicting the GBPPs in AP can be classified into those related to Fuel Allocation and Availability, Fuel Tie-up and Fuel Supply Agreements, Power Purchase Agreements, Infrastructure for Alternative Fuels.
In its endeavour to encourage private sector to invest in the power sector, the government removed the entry barriers. This has led to a plethora of entrants into the sector, with or without the requisite experience – mostly without, which is quite natural as power generation has always been in the domain of public sector. If one looks at the reforms of the Power Sector, we find that the job is half-finished as can be seen here:
Prior to reforms, the entire risk from investment to generation, transmission and distribution was being borne by the state electricity boards or the central power producers. Post reforms, the risk of investment, project construction/ implementation, operation and maintenance is shifted to the private entrepreneur. Besides, with the fuel allocation and purchase of power being retained within the domain of the government, the private entrepreneur has to bear the risks associated with it, as the same are not truly market determined.
Effect of ‘Fuel Supply Controls’
Nowhere in the world would a project be financed without upfront tie-up of fuel for the entire period of loan servicing. But in India, a private entrepreneur has to commit his equity and the lender has to commit its loans for the project without any certainty whatsoever as to whether the project would really get the gas required for successfully operating the project. The uncertainty lies in not just in the availability, but also in the quantum and the period of availability.
Typically, a project is appraised by a financial institution based on the terms of PPA, which mandates achievement of at least an annualised average PLF of 80% (now 85%). To achieve this, the plant should operate at PLF over 87% for the 11 months that it would be in operation, setting aside one month’s mandatory maintenance period, called minor or major inspection. The financial institution appraises the viability of the project on the assumption of gas availability at this level. The entrepreneur too expects the gas availability at this level to achieve mandated PLF.
The allocation of gas to the various power plants by MoPNG, however, is more by rationing the available gas than by any rationality of plant operation. At present, the gas allocation is done at 70% of a plant’s requirement at 100% PLF, and for those plants in AP, where the gas wells are located, the allocation is higher by 5%. No amount of engineering would help a plant achieve 87% PLF (or 80% PLF on an average) with 70% gas availability. What happens to a plant that is to and that should operate at over 85% PLF actually operates at sub-70% PLF? To say the least, it bleeds.
A plant that operates at 70% PLF will have higher Station Heat Rate (SHR), which essentially means that the plant uses more fuel to generate a kWh (unit), than it is expected to, making it energy-inefficient that translates into higher unit cost of generation. One may argue that the fuel cost is a pass-through. However, the Power Purchase Agreement has a locking mechanism by which the Energy Charges payable by the DISCOMS would be paid using a pre-fixed SHR (let us call it Hurdle Station Heat Rate or H-SHR). The Energy Charges are arrived at by applying the H-SHR for the units supplied, resulting in under-recovery of Energy Charges and therefore revenue loss.
For example, given a calorific value of one unit of gas (measured in Standard Cubic Meters, or SCM) of say, 9,250 Kcal and the given PPA-stipulated H-SHR of 1850 kcal/kWh, one SCM should generate 5 units (kWh). If the actual station heat rate is higher at say 2000 kcal/ kWh, only 4.625 kWh can be generated with one SCM. Thus, for the same quantum of gas consumed, the loss of generation for each SCM is 0.375kWh. If a plant consumes 2MMSCMD, the loss of generation will translate into 750,000kWh per day or 31.25MWh. At Re.1 per kWh as Capacity Charge, assuming fuel cost being pass-through, the revenue would be lower by Rs.750,000 per day or Rs.2.25 crore per month.
Thus, the plant loses revenue on account of the following:
- Sub-optimal allocation of NG by GOI forces the plant to operate at lower PLF, which means lower generation and lower revenue.
- Lower PLF results in higher SHR, which translates into lower generation per unit of gas consumed.
- SHR higher than H-SHR results in under-recovery of Energy Charges even when the same are pass-through.
The short-supply of Natural Gas forces the GBPPs to idle hundreds of MW of power generation capacity resulting in losses in millions of rupees every day, though the losses are somewhat alleviated whenever regasified LNG is made available to these plants. This enormous loss of revenue is caused by an externality – the intervention of the government in the gas procurement process. The private entrepreneur who has set up the plant taking the risks of investment, construction and operations is forced to bear the revenue loss caused by the irrational allocation of fuel. This risk was unknown to the investor when the investment decision was made. The ideal way for GOI is to allow plants to come up only to the extent of NG availability.
Power Purchase Agreement
The anomalous situation explained above can be corrected if the power purchase agreement (PPA) with the DISCOMs is made flexible and practical. Typically the PPA is valid for 10-15 years. The main provision of PPA is the Tariff structure, guided by the Hurdle Station Heat Rate and the PLF the plant is expected to achieve on an average. One of the components of the Tariff is the fuel cost, which can be either a pass-through or not. The other component, the Fixed Charge or the Capacity Charge, is payable based on plant availability. The H-SHR is incorporated in the PPA that is signed ahead of project appraisal by the lenders, i.e., even before the investment is made.
The main feature of a PPA is that the tariff over the period of PPA remains unchanged, notwithstanding any abnormal inflationary pressures and the derating of the plant that is bound to happen. Station Heat Rate of a plant varies inter alia with the make and model of power equipment installed in the plant, the ambient conditions, besides PLF. SHR also goes up with the derating of the plant by which its efficiency naturally goes down with every passing year of operation.
The PPA structure is essentially dictated by a system of monopsony, which leaves little room for negotiations for the entrepreneurs, who are always the weaker party. The PPA thus throws up the following challenges to the private sector entrepreneur:
- The tariff remains the same over the PPA, not considering abnormal inflation over the PPA term.
- The H-SHR is kept constant, even though
a. the power equipment varies from plant to plant,
b. derating of the plant takes place over the operating years resulting in lower efficiencies,
c. natural gas availability is lower than the required level due to any externality.
The PPA is inflexible to this extent. While derating of the plant and inflation are taken into account to a certain extent when one arrives at the equalised/ levelised tariff, the abnormalities such as lower gas ‘allocation’ by the GOI are never considered. A more rational approach would be to base PPAs on the following principles:
- Tariffs have to be set to recover total industry costs, for the investments to be viable as well as ensuring long-term sustainability of the Sector
- “Actual” versus “Allowed” costs – forecasting errors and information asymmetry mean that these are inevitably different – but allowed costs should normally be used, but with rider for correction along the way to take care of abnormalities caused by externalities.
If one applies the above principles, the PPA should capture the abnormality of short-allocation of gas supply by incorporating a provision to change the H-SHR to nullify the adverse impact of such abnormality on the operations of power plants.
Prior to reforms, such abnormalities were being addressed by the government itself through policy changes or by cross-subsidisation. With the PPAs as they are structured now, the burden of subsidies by the government is indirectly passed on to the IPPs. Therefore there is every need to standardise the PPAs built on the ideal principles stated above to ensure long-term sustainability of the Sector.
Alternative Fuels
It is but quite natural for an entrepreneur who has invested billions of rupees in a project to look for alternative fuels to run the plant when the allocation of gas by the government falls short of the requirement. One of the obvious options is LNG, which can be re-gasified (called R-LNG) and used as fuel. There are no LNG terminals on the east coast in AP to import and receive LNG. The only LNG terminal on the east coast is at Chennai, which too is still in planning stage. All other LNG terminals, operating or under implementation, are on the west coast at Dahej, Hazira in Gujarat, Ratnagiri in Maharashtra and Kochi in Kerala. Unless more LNG terminals are built on the east coast, the RLNG has to be transported from the west coast or the RLNG consumption in the west coast and NG consumption on the east coast have to be swapped as a pre-agreed arrangement to optimise gas transportation. However, the issues related to taxation and cost of transportation have to be addressed, without which the landed cost of RLNG remains prohibitive and defeats the purpose. It is understood the MoPNG is working on the guidelines for gas swapping. There is also an urgent need to build LNG terminals with interconnecting pipelines on the east coast.
Revisiting Regulatory Framework
The above situation of conflicting interests and lack of level-playing field for the IPPs on one hand, the natural gas allocation, its suppliers and transporters and the power purchasers on the other due to existence of monopsony and natural monopolies, begs the question, whether the current regulations has to be redefined, and if so, how?
At one level, the task of allocation of gas currently vested with the MoPNG may be hived off to a new and independent regulatory body. The regulatory body should be vested with the powers to rationally allocate, rather than ration out, Natural Gas, introduce standardised gas supply and purchase agreements that are equitable, determine gas pricing and transportation pricing that is multi-laterally beneficial to all stakeholders, and remove the anomalies brought about by the natural monopolies in gas sales and transportation to help establish sustainable generating capacities in the country.
Today, even though there is more than one DISCOM in each state, when it comes to floating bids, or purchasing electricity, they act in unison as a single body, defeating the very purpose of introducing competition. The ideal way is to introduce competition among the DISCOMs by removing the geographic delineation. This will help a plant to sell its electricity generated to more than one DISCOM and at different prices. A utopian scenario is wherein all power generated in the country is offered on a trading platform with forward contracts.
Similarly, the current electricity regulatory bodies should not only continue to serve the larger interest of the public, they should also look at the long-term viability of the projects and hence the Power Sector as a whole, to retain it investor-friendly, before it is too late. This will be the most important element in making the electricity reforms successful. If government wants to retain control of certain aspects of the value chain, it should ensure that the burden and risks are borne equitably and not by the industry alone, else, the entire value chain should be made entirely market-driven.
